When producing oil and/or gas from an unconsolidated subterranean formation, some type of particulate control procedure may be required in order to prevent sand grains and/or other formation fines from migrating into the wellbore and being produced from the well. The production of such particulate materials can reduce the rate of hydrocarbon production from the well and can cause serious damage to well tubulars and to well surface equipment.
Those skilled in the art have commonly used gravel packs to control particulate migration in producing formations. A gravel pack will typically consist of a mass of particulate material which is packed around the exterior of a screening device, said screening device being positioned in an open hole or inside a well casing. Examples of typical screening devices include wire-wrapped screens and slotted liners. The screening device will typically have very narrow slots or very small holes formed therein. These holes or slots are large enough to permit the flow of formation fluid into the screening device but are too small to allow the particulate packing material to pass therethrough. In conjunction with the operation of the holes or slots formed in the screening device, the particulate packing material operates to trap, and thus prevent the further migration of, formation sand and fines which would otherwise be produced along with the formation fluid.
Hydraulic fracturing techniques are commonly used to stimulate subterranean formations in order to enhance the production of fluids therefrom. In a conventional hydraulic fracturing procedure, a fracturing fluid is pumped down a wellbore and into a fluid-bearing formation. The fracturing fluid is pumped into the formation under a pressure sufficient to enlarge natural fissures in the formation and/or open up new fissures in the formation. Packers can be positioned in the wellbore as necessary to direct and confine the fracturing fluid to the portion of the well which is to be fractured. Typical fracturing pressures range from about 1,000 psi to about 15,000 psi depending upon the depth and the nature of the formation being fractured.
Fracturing fluids used in conventional hydraulic fracturing techniques include: fresh water; brine; liquid hydrocarbons (e.g., gasoline, kerosene, diesel, crude oil, and the like) which are viscous or have gelling agents incorporated therein; gelled water; and gelled brine. The fracturing fluid will also typically contain a particulate proppant material. The proppant flows into and remains in the fissures which are formed and/or enlarged during the fracturing operation. The proppant operates to prevent the fissures from closing and thus facilitates the flow of formation fluid through the fissures and into the wellbore.
Frac-pack operations are primarily used in highly unconsolidated and semi-consolidated formations to facilitate fluid recovery while preventing particulate migration. A frac-pack operation typically embodies the features of both a fracturing operation and a gravel packing operation. Preferably, the unconsolidated formation is initially fractured using a proppant-laden fracturing fluid. The proppant material deposits in the fractures which are formed during the fracturing operation. Due to the unconsolidated nature of the formation, the fractures produced during the fracturing step will typically be substantially wider and shorter than the fractures produced when fracturing consolidated formations. After a desired degree of fracturing is achieved, additional proppant material is tightly packed in the wellbore. The additional proppant material will typically be held in place in the wellbore by (a) packing the proppant material around a gravel packing screen and/or (b) consolidating the proppant material by means of a resin coating.
Examples of particulate materials commonly used for gravel packing and frac-pack operations and as fracturing proppants include: sand; glass beads; nut shells; metallic pellets or spheres; gravel; synthetic resin pellets or spheres; gilsonite; coke; sintered alumina; mullite; like materials; and combinations thereof.
Consolidatable resin-coated particulate materials have been used heretofore in various well treatment operations. Consolidatable resin-coated sands have been used, for example, for gravel packing, for frac-pack operations, and as proppant materials in formation fracturing operations. Due to their desirable permeability and compressive strength characteristics, resin-coated particulate materials are especially well-suited for treating semiconsolidated and unconsolidated formations which contain loose or unstable sands.
As used herein, the term "consolidatable resin-coated particulate material" refers to a particulate material (e.g., a proppant, a particulate gravel packing material, or a particulate material used for frac-pack operations) which is coated with a bonding-type resin composition (e.g., an epoxy resin composition, a phenol/aldehyde type resin composition, etc.). Typically, the consolidatable resin-coated composition particulate material will be injected into a subterranean zone using procedures whereby the resin does not substantially harden until after the particulate material has been delivered to a desired location within the formation. The hardening of the resin consolidates the particulate material to yield a hard, consolidated, permeable mass.
Well treatment methods utilizing consolidatable epoxy resin-coated particulate materials are disclosed, for example, in U.S. Pat. No. 5,128,390. Well treatment methods utilizing consolidatable resole-type phenolic resin-coated particulate materials are disclosed, for example, in U.S. Pat. No. 4,336,842. The entire disclosures of U.S. Pat. Nos. 4,336,842 and 5,128,390 are incorporated herein by reference.
U.S. Pat. No. 5,128,390 discloses a method for continuously forming and transporting consolidatable resin-coated particulate materials. In the method of U.S. Pat. No. 5,128,390, a particulate material (e.g., sand) and a hardenable epoxy resin system are continuously mixed with a stream of gelled carrier liquid. The resulting continuous composition is delivered to and/or injected into a desired subterranean zone. As the continuous mixture flows down the well tubing toward the subterranean zone, the composition ingredients are mixed such that the gel-suspended particulate material is thoroughly coated with the hardenable epoxy resin system. After being placed in the subterranean zone, the epoxy resin composition is allowed to harden whereby the resin-coated particulate material forms a hard, permeable, consolidated mass.
The hardenable epoxy resin composition used in the method of U.S. Pat. No. 5,128,390 is generally composed of: a polyepoxide resin carried in a solvent system; a hardening agent; a coupling agent; and a hardening rate controller.
U.S. Pat. No. 4,336,842 disclosed methods for treating wells using resin-coated particles. As indicated above, the methods of U.S. Pat. No. 4,336,842 preferably utilize one-step phenolic resins which are prepared by reacting phenolic compounds with aldehydes in the presence of alkaline catalysts. Such resins are commercially available in both powder and liquid form. Examples of suitable phenolic compounds include: phenol; resorcinol; alkyl substituted phenols (e.g., cresol and p-tert-butyl phenol) and cardanol. Examples of suitable aldehyde compounds include: formaldehyde; acetaldehyde; and furfuraldehyde. The specific resin-coated particulate materials disclosed in U.S. Pat. No. 4,336,842 are free-flowing, pre-coated particulate materials. Such pre-coated particulate materials can be prepared, for example, by (a) dissolving the powdered phenolic resin in a solvent, mixing the particulate material with the resulting resin solution, and then evaporating the solvent or (b) using a heat coating process wherein the particulate substrate material is heated and then mixed with the powdered resin.
In one embodiment of the methods of U.S. Pat. No. 4,336,842, a pre-coated particulate material of the type just described is used in a formation fracturing operation. The formation fracturing operation includes the steps of: generating a fracture in the formation by pumping a viscous fluid into the formation at a pressure and at a rate sufficient to fracture the formation; continuing the viscous fluid pumping step until a desired fracture geometry is obtained; mixing the pre-coated particulate material with a carrier fluid; pumping the carrier/particulate mixture into the formation such that the pre-coated particulate material deposits in and fills the fracture; pumping a curing solution into the formation such that the curing solution contacts the pre-coated particulate material; and then allowing the resin coating to fuse and cure at the elevated temperature conditions existing in the formation. Upon curing, the resin coated particulate material forms a hard, permeable mass. The curing solution used in U.S. Pat. No. 4,336,842 includes a resin softening agent capable of lowering the fusion temperature of the resin coating. Examples of suitable softening agents include: alcohols which are at least partially soluble in the resin; nonionic surfactants; and combinations thereof.
In other embodiments of the methods of U.S. Pat. No. 4,336,842, pre-coated particulate materials of the type described above are used in conventional gravel packing operations. Examples include open-hole gravel packs, inside-the-casing gravel packs, and linerless gravel packs. After the gravel pack is in place, a curing solution of the type described above is pumped into the formation such that the solution contacts the pre-coated particulate material. The well is then shut-in in order to allow the resin coating to fuse and cure at the elevated temperature conditions existing in the formation.
Heretofore, in conducting a fracturing, gravel packing, frac-pack, or similar well treating operation, the particulate material used has typically consisted of particles lying within a single, relatively narrow size range (e.g., 20/40 mesh, 40/60 mesh, or 50/70 mesh). As used herein and in the claims, a term such as "20/40 mesh" refers to a material having a particle size distribution lying entirely within the range of from 20 to 40 mesh, U.S. sieve series. Thus, the particles of a 20/40 mesh material would be smaller than 20 mesh, U.S. sieve series, but not smaller than 40 mesh, U.S. sieve series.
The specific particle size selected for use in a given application has primarily depended upon (a) the degree of unconsotidation existing in the formation (i.e., the degree to which the formation contains loose sand and fine materials which would otherwise migrate through the formation and into the well tubing), (b) the particle size distribution of the natural sand and fine materials comprising the formation, and (c) the desired product flow rate to be obtained from the formation.
Heretofore, the selection of an appropriately sized particulate material for treating an unconsolidated or semi-consolidated formation has involved an undesirable trade-off. The use of a large particulate material (e.g., 12/20 mesh or 20/40 mesh) provides a high initial permeability and a correspondingly high initial production rate. However, the migration of formation sand and fines into the large material eventually clogs fluid passageways within the material bed and thereby reduces the production rate sustainable through the bed. Additionally, the eventual migration of formation sand and fines through the bed and into the wellbore can cause severe damage to the well tubulars and other production equipment. The use of a small particulate material (e.g., 40/60 mesh, 50/70 mesh, or 60/80 mesh), on the other hand, substantially prevents the migration of formation sand and fines into and through the particulate bed. However, small particulate materials have relatively low permeabilities and therefore yield substantially reduced production rates.
The most commonly used gravel packing material is believed to be 20/40 mesh resieved sand.
Thus, a need presently exists for fracturing, frac-pack, gravel packing, and similar treating techniques wherein the particulate materials used will both (a) prevent the migration of formation sand and fines and (b) provide high relative production rates.
U.S. Pat. No. 4,478,282 discloses a hydraulic fracturing technique wherein adverse vertical height growth of induced fractures is controlled by the injection of a non-proppant fluid stage. The non-proppant fluid stage comprises a transport fluid and a flow blocking material. The flow blocking material has a particle size distribution which is sufficient to form a substantially impermeable barrier to vertical fluid flow. The method of U.S. Pat. No. 4,478,282 includes the steps of (a) injecting a fracturing fluid pad into the formation at a sufficient rate and pressure to open a fracture in the formation, then (b) injecting the non-proppant fluid stage into the formation, and then (c) injecting a proppant-laden slurry into the formation.
The particulate material used in the non-proppant fluid stage of the method of U.S. Pat. No. 4,478,282 consists of a large particulate material (i.e., 10/20 mesh and/or 20/40 mesh) and a very small particulate material (i.e., smaller than 100 mesh). The large particulate material creates particle bridges within the formation fracture. The very small particulate material, on the other hand, fills the gaps existing between the larger particles and forms a substantially impermeable barrier to fluid flow.
Thus, the method of U.S. Pat. No. 4,478,282 neither addresses nor resolves the particulate migration and production rate problems discussed above. Rather, as will be apparent, U.S. Pat. No. 4,478,282 teaches away from the invention described and claimed herein below.
U.S. Pat. No. 4,665,988 discloses a method of filling a void in a subterranean formation. The method includes the steps of: (a) admixing a first particulate material, a second particulate material, and a resin composition with a viscous carrier fluid; (b) introducing the resulting mixture into the subterranean formation such that the void is filled by the mixture; (c) compacting the particulate material in the void by applying fluid pressure to the mixture; and (d) allowing the resin composition to harden such that the particulate materials are consolidated and a permeable mass is formed within the void. The first particulate material used in the fill composition has a particle size of no greater than 10 mesh. The second particulate material used in the fill composition has a median diameter of less than 1/7 the median diameter of the first particulate material. After the resin composition hardens, any excess fill material remaining in the wellbore can be drilled out and a suitable liner is then installed in the wellbore and cemented in place to thereby isolate a selected zone of interest.
Thus, U.S. Pat. No. 4,665,988 neither discloses nor suggests a means by which fracturing, gravel packing, frac-pack, and similar techniques can be improved to (a) provide high fluid production rates while (b) preventing the migration of formation particulates into the wellbore. Rather, U.S. Pat. No. 4,665,988 discloses only a secondary or tertiary production technique wherein existing formation voids adjacent a wellbore are filled with a permeable mass prior to inserting a new casing into the wellbore and cementing the casing in place.
U.S. Pat. No. 4,969,523 purports to provide a gravel packing method wherein equivalent packing efficiency is obtained in the upper and lower perforations and portions of the wellbore annulus. The method comprises injecting a particulate/carrier fluid slurry into the wellbore wherein the particulate material includes first particles having a density less than the density of the carrier fluid and second particles having a density greater than that of the carrier fluid. U.S. Pat. No. 4,969,523 also discloses the performance of a comparative test which utilized a mixture of 20/40 mesh sand having a density of 2.65 and 18 to 50 mesh styrenedivinylbenzene beads having a density of 1.05. Thus, U.S. Pat. No. 4,969,523 neither addresses nor resolves the specific particulate migration and production rate problems discussed above.